It is a common practice to employ acid stimulation of low-permeability or damaged carbonate reservoir formations in order to enhance the flow and production of hydrocarbon fluids from the formation surrounding the wellbore. Acid treatment of water injection wells is similarly employed to enhance the permeability of the reservoir. However, the effectiveness of the acid treatment can be seriously reduced if the wellbore contains formation damage caused by incursions of drilling fluids, or mud, and other foreign matter. This problem is particularly pronounced in water injection wells through tight carbonate reservoir formations and results in acid treatments that are less successful than those carried out in relatively high permeability water injection wells.
The effectiveness of the acid treatment is directly proportional to the injection rate (e.g., barrels of water/minute) and inversely proportional to the injection pressure, i.e., a lower pressure is required for a given injection rate following an effective acid treatment.
It has been found that hydrochloric acid which can effectively dissolve the calcium carbonate minerals present in both the filter cake and the formation is not capable of dissolving or degrading some of the formation-damaging polymer components present in the drilling fluid, such as xanthan gum and starch. The xanthan gum is used to increase viscosity and the starch to control fluid loss. Three different damage mechanisms associated with drilling fluids are filtrate invasion, solid invasion (internal filtercake) and external filtercake. Other materials used in assembling the drilling pipe can also cause damage to the surrounding formation. Pipe dope applied to the couplings and other fittings used in assembling the drilling pipes and associated components can also cause damage to the surrounding formation.
As used herein, the term “undesirable materials” will be understood to refer to formation-damaging polymers, other chemical substances, debris and other materials which interfere with the flow of formation fluids from the walls and adjacent reservoir rock of the well bore and thereby reduce the productivity/injectivity of the well. The inherent formation pressure is the pressure of the fluids in the pores of a reservoir created by the weight of the overburden, water injection and any underground withdrawal.
As used herein, the term “wellbore” if not otherwise modified, will be understood to mean the combined vertical section and the open-hole horizontal section of the well.
It is therefore an object of the present invention to provide a method of substantially eliminating or greatly reducing the presence of formation-damaging materials, such as polymer components and pipe dope residue that interfere with the effectiveness of an acid stimulation treatment in an open-bore horizontal water injection well, to thereby render the subsequent acid treatment of the formation more efficient and effective.